Natural gas streams that contain low levels of acid gases and other contaminants can be economically treated by a wide variety of known treating processes. However, with increasing acid gas and other contaminant content, current treating processes often require relatively large quantities of energy and may further require additional processing equipment.
An exemplary known gas treatment configuration that employs the use of a physical solvent is depicted in prior art FIG. 1 in which an absorber 203, a flash drum 205, a recycle compressor 206, exchanger 207, a solvent regenerator 208, a reboiler 209, a solvent pump 216, and a refrigerant chiller 217 are configured to remove hydrogen sulfide and contaminants from a feed gas (Further components of this plant include sulfur plant 213, hydrogenation and quench unit 214 and tail gas unit 215). It should be recognized that such plants are typically not selective in the removal of H2S and contaminants (i.e., co-absorption of CO2 by the solvent is relatively high). Particularly, when the feed gas 1 comprises relatively large CO2 quantities (e.g., greater than 50%), co-absorption of CO2 in such plants requires higher solvent circulation and higher energy consumption and also produces an acid gas rich in CO2 (typically 80%) that is an undesirable acid gas for the sulfur plants. As a result, and especially where the feed gas comprises relatively high concentrations of acid gas and other contaminants, the capital and operating costs required by these processes are generally very high. Very often, post treatment of the treated gas from these units with additional processing equipment is required, due to the fact that elimination of contaminants is frequently below desirable levels.
To circumvent at least some of the problems associated with inadequate contaminant removal, various post treatment methods of treated gases have been employed. Unfortunately, most of such methods tend to be relatively inefficient and costly, and where contaminants are removed by a fixed bed absorbent process, they may further pose a disposal problem for the spent absorbent. Therefore, various problems associated with operating efficiency, effluents; emissions, and product qualities, particularly in the downstream sulfur recovery unit and tail gas unit, still remain. For example, acid gas produced from such treating processes is generally poor in quality (e.g., comprising significant quantity of contaminants, and/or a relatively large quantity of co-absorbed CO2 and hydrocarbons), which often requires additional processing and higher energy consumption, thereby increasing the overall capital and operating costs of the sulfur plant. Furthermore, co-absorbed hydrocarbons in the acid gas must generally be converted to CO2 in the sulfur plant, which results in an increase in CO2 emissions from the process. Thus, despite the significant potential energy value in the hydrocarbons, most of the currently known processes fail to recover these waste hydrocarbon streams as a valuable product.
In other known processes, a tail gas unit is often used to control the sulfur emissions from the sulfur plant. Even if the emission is reduced to a very low ppm level, the total quantity of annual sulfur emissions (tons/year) in the vent stream is still relatively high, due to relatively large venting rates attributed to the large co-absorbed CO2 in the treating process. Moreover, contaminants and hydrocarbons in the acid gas of most known gas treatment configurations are often not completely destroyed in the sulfur plants, and the sulfur product will therefore be contaminated with unconverted hydrocarbons and mercaptans and will thus become an additional industrial waste disposal problem.
Therefore, while various gas processing treatments and configurations are known in the art, all or almost all of them suffer from one or more disadvantages, and especially where the feed gas comprises relatively high levels of acid gases, hydrocarbons and other contaminants.